A giant brownfield re-development project with long horizontal wells was initiated to arrest production decline mainly caused by a lack of pressure support and free gas influx from the large gas cap.
Key value drivers for the project are developing an understanding of the layers with regards to gas breakthrough, and achieving capital efficiency through low-cost well delivery, better planning and technology applications.
Firstly, the field has been segmented based on the analysis of multiple factors influencing the free gas production. It considers geological aspects such as the study of depositional environment and diagenesis, structural elements such as high permeability streaks and fractures, dynamic behaviors such as the water injection efficiency, gas cap expansion or coning.
Secondly, numerical simulations were then run in order to rank the sectors based on the expected model performance, compare them with real data categorization, and test the effect of the new proposed development schemes such as water injection at gas-oil contact and long horizontal wells equipped with downhole control valves.
It was found that each sector has a specific production mechanism and appropriate developments were recommended and then tested in the simulation. For instance, high permeability streaks play a significant role on the development of some sectors instigating a big difference of maturity between sub-layers, early water or gas breakthrough. Also, the inefficiency of water injection is one of the biggest issues of the field. Most of the water injectors are located too far from the oil producers, and have a low injectivity due to the often degraded facies in the aquifer because of diagenesis. This leads to a lack of pressure support that is counterbalanced by the gas injection, ending up with a lot of high GOR wells and a bad sweep from the top of the structure as the gas tends to by-pass the oil.
Simulation work showed that several remaining zones are safe for immediate development and should be prioritized for development in the near future. On the other hand, some of the mature layers prone to gas and water breakthrough need a boost for development, such as water injection at gas-oil-contact, artificial lift, low pressure system, GOR relaxation. Tight and undeveloped reservoirs are improved by implementing long horizontal drains.
Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Next, appropriate depth methods will be presented. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process.
A numerical simulation study was conducted to explore feasibility of gas cap and oil column co-development plans. Unlike conventional development schemes that entail to optimally produce first from oil column while deferring gas cap development, the co-development strategy studied here involves simultaneous production from oil column and gas cap. The drive mechanism consists of down-dip peripheral water injection for oil column in conjunction with barrier water injection at or near gas-oil contact that is designed to separate the gas cap from the oil column and thereby facilitate gas production. The basic objective of the study is twofold: to assess the merits of the concept of barrier water injection and to identify key subsurface and operational parameters that have most significant impact on oil and gas recovery. Extensive numerical simulations were conducted to explore the conditions under which the concept of barrier water injection is favourable as a recovery process. Important issues related to the viability of the development concept are how fast a barrier water can be established, how long it can be sustained and how many wells are needed. Furthermore, effects of gas cap relative size, reservoir geometry (e.g., dip-angle and surface area of the gas-oil contact), trapped gas, rock heterogeneity and off-take rates have been investigated in detail. The work shows that the feasibility of the co-development scheme is mainly controlled by pressure maintenance and balance of injection, relative size of gas cap, reservoir geometry and rock heterogeneity.
Polymer flooding is a mature Enhanced Oil Recovery process which is used worldwide in many large- scale field expansions. Encouraged by these positive results, operators are still looking at applying the process in new fields even in the context of low oil prices and are evaluating its feasibility in more challenging reservoir conditions: high salinity, high hardness and high temperature. Several solutions have been proposed to overcome the limitations of the conventional hydrolyzed polyacrylamide (HPAM) in these types of challenging environments: biopolymers such as xanthan or scleroglucan, associative polymers, or co- or ter-polymers combining acrylamide with monomers such as ATBS or NVP. Each of these solutions has its advantages and disadvantages, which are not always clear for practicing engineers. Moreover, it is always interesting to study past field experience to confront theory with practice. This is what this paper proposes to do.
The paper will first review the limits of conventional HPAM and other polymers that have been proposed for more challenging reservoir conditions. But more than that, it will focus on the field experience with each of these products to establish some practical guidelines for the selection of polymers depending on the reservoir and fluid characteristics.
One first result of this review is that the limits of conventional HPAM may not be as low as usually expected. Biopolymers appear very sensitive to biodegradation and their success in the field has been limited. Associative polymers appear better suited to near-wellbore conformance control than to displacement processes and some of the new co and ter-polymers are currently being field tested with some measure of success. It appears that the main challenge lies with high temperature rather than high salinity; some field projects are currently ongoing in high salinity (200 g/L) and hardness.
The paper will help set the current limits for polymer flooding in terms of temperature, salinity and hardness based on laboratory work and field experience. This will prove a useful guide for practicing engineers looking to pilot polymer injection in challenging reservoir conditions.
Puskas, S. (MOL Hungarian Oil and Gas Plc.) | Vago, A. (MOL Hungarian Oil and Gas Plc.) | Toro, M. (MOL Hungarian Oil and Gas Plc.) | Ordog, T. (MOL Hungarian Oil and Gas Plc.) | Kalman, G. (MOL Hungarian Oil and Gas Plc.) | Hanzelik, P. (MOL Hungarian Oil and Gas Plc.) | Bihari, Zs. (MOL Hungarian Oil and Gas Plc.) | Blaho, J. (MOL Hungarian Oil and Gas Plc.) | Tabajdi, R. (University of Szeged) | Dekany, I. (University of Szeged) | Dudas, J. (University of Pannonia) | Nagy, R. (University of Pannonia) | Bartha, L. (University of Pannonia) | Lakatos, I. (University of Miskolc.)
Central element of MOL Hungarian Oil and Gas Plc. (MOL) US strategy is to increase the hydrocarbon production at Hungarian oil and gas fields using technologies that are more efficient. The main goals of this activity are to increase the recovery factor in fields depleted with extensive water flooding, improving efficiency of recovery technologies. For this purpose, new materials and technologies should be developed and applied at both Hungarian and foreign matured oil fields. That is the biggest challenge of the research and development (R&D) activity of the MOL Upstream. The R&D project began more than ten years ago to meet these challenges and increase the oil recovery factor of the Algyo field, which is the largest Hungarian oil field. This paper describes how a countless number of surfactants, co-surfactants and their mixtures were synthetized, developed and tested in the laboratory to achieve the objective, developing a combined surfactant-polymer (SP) flooding technology. The most important properties of these complex fluids were the thermal stability at reservoir conditions (98°C and 170 bar), the colloid chemical stability in electrolyte medium (formation water) and the compatibility with reservoir rock and pore filling fluids. The primary findings of this job show that several surfactants were effective at high temperature; low salinity reservoir conditions and have good solubilisation and displacement effect and low interfacial tension and low reversible adsorption on reservoir rock. Synergetic effect was observed between surfactants and polymers therefore surfactant-polymer mixtures were produced and tested in core flooding tests. Based on numerous displacement tests on reservoir core plugs it can be stated that the calculated recovery factor was 20-25% using the developed SP mixtures. The successful laboratory displacement tests were also reproduced by numerical simulation on numerical core samples as well as the injectivity test on the new 3D reservoir model that was carried out to see the effect of developed SP mixture under real reservoir conditions. This paper will present the results of several years of research and development work for SP formulation targeting SP flooding in high pressure and high temperature reservoir. The field implementation through an injectivity test will also be presented demonstrating that injection of 2,000 m3 SP solution has huge effect on oil production even 3 years later. Based on the outstanding field results a SP flooding pilot was started in 2016.
Lakatos, I. (University of Miskolc, Research Institute of Earth Scieces) | Lakatos-Szabo, G. (University of Miskolc, Research Institute of Earth Scieces) | Szentes, G. (University of Miskolc, Research Institute of Earth Scieces)
Reservoir conformance control (RCC) might be fundamental designingprofitable production technology in oilfields. Appropriate application of RCC methods can significantly results inimproved IOR/EOR throughreduced water production and profile correction. In the past decades, numerous techniques were extensively applied with these goals including macro- and microgels, emulsions, sols, crystalline compounds, etc. Surprisingly, the use of silicates was not really appreciated by the operators despite the fact that silicates were proposed for chemical EOR and profile control already in 1922. In the past decades, the silicate technology has a revival because of their outstanding features and these methods are superior to other gel technical solution. The review is summarizing both the old and the new results of laboratory research and the case histories. Recently, emblematic professionals proposed the silicate gels as efficient alternatives to other gel technologies. As a result, the attitude towards the extensive use of silicates in oil fields changed. Therefore, the presentation overviews the silicate conformance treatments and its advanced hybrid systems. They were used more than hundred times in Hungary, Serbia, Norway, USA, Oman, and other countries for water shutoff, profile correction, restriction of gas conning, mitigation of vertical CO2 migration in wells, remediation of leak-off by fractured casing, stimulation of wells operating in harsh environment, and mobility control in CO2 flooding.
The presentation summarizes the results of pilots and routine applications, and critically analyzes the lessons to learn. Base on the publications disseminated until now it can be concluded that the field jobs demonstrate outstanding statistics. It will also be shown that the diverse silicate RCC methods may attract attention because they can be efficiently used with high flexibility in all types of porous and fractured reservoirs. The in-situ formed silicate gels have excellent thermal stability up to 150°C, the chemicals are available at low price, the job needs simple surface facility, customary human force, and the methods are environmental friendly. Consequently, the silicate methods may open new vistas in brown field operations curing problems arising at oil and gas fields even in time of volatile oil and gas price.
Schedule Session Details Expand All Collapse All Filter By Date All Dates Sunday, November 12 Monday, November 13 Tuesday, November 14 Wednesday, November 15 Thursday, November 16 Filter By Session Type All Sessions Social and Networking Events Technical Sessions Panel, Plenary, and Special Sessions Training Course/Seminar Sunday, November 12 08:00 - 17:00 Production Optimisation System Instructor(s) Atef Abdelhady The basic objective of this course is to introduce the overview and concept of production optimisation, using nodal analysis as a tool in production optimisation and enhancement. Learn More 08:00 - 17:00 Practical Depth Conversion and Depth Imaging for the Interpreter Instructor(s) Pavel Vasilyev Depth conversion of time interpretations is a basic skill set for interpreters. There is no single methodology that is optimal for all cases. Depth imaging should be considered an integral component of interpretation. If the results derived from depth imaging are intended to mitigate risk, the interpreter must actively guide the process. Participants will gain an understanding of depth conversion methodologies and QCs for validity of methods used. Learn More 08:00 - 17:00 Marginal Field Development and Optimisations Instructor(s) Abdolrahim Ataei Green fields today mostly can be regarded as marginal fields and successfully developed. It covers the complete assessment of the oil and gas recovery potential from reservoir structure and formation evaluation, oil and gas reserve mapping, their uncertainties and risks management, feasible reservoir fluid depletion approaches, and to the construction of integrated production systems for cost effective development of the green fields. This session will show how chip technology has resulted in a miniaturised Electron Paramagnetic Resonance (EPR) spectrometer for online monitoring of asphaltenes (a chemical that clogs oil wells). The EPR sensor technology developed in the laboratory has been successfully deployed in major oil and gas fields across the world. This technology is used to monitor the concentration of asphaltenes in real-time and to minimise the use of environmentally hazardous chemical inhibitors in energy production. Employee suggestions for improvement cover a wide variety of topics such as economic efficiency, productivity, safety, operability, environmental friendliness, and to a greater or lesser extent, has led to efficient and improved operations.
Reservoir conformance control (RCC) might be fundamental designing profitable production technology in oilfields. Appropriate application of RCC methods can significantly result in improved IOR/EOR through reduced water production and profile correction. In the past decades, numerous techniques were extensively applied with these goals; however, the operators did not appreciate the silicates until mid-1970s despite the fact that emblematic professionals proposed the silicate gels as efficient alternatives to organic gel technologies. Recently, the attitude towards the extensive use of silicates in oilfields has changed. The silicate-based water shutoff treatments and profile control methods have been already used more than hundred times in Hungary, Serbia, Norway, USA, Oman, and other countries. In the past several years, the fundamental and applied research focused on elimination of inherent negative properties of pure silicate gels, and development of efficient and flexible technologies using polymers and nanosilica in the treating solutions. As a result, the diverse silicate RCC methods arouse high interest in oilfield applications. Today, the
The presentation summarizes the results of both the fundamentals and a pilot tests accomplished in the Algyő field, and critically analyzes the lessons to learn. Base on the publications disseminated until now it can be concluded that these field jobs demonstrate outstanding responds both in water cut and increased oil rate. It was also proved that the nanoparticle-induced (nucleated) formation of silicate gels could potentially be used in all types of porous and fractured reservoirs. In addition, the in-situ formed gels have outstanding thermal stability up to 150°C, the chemicals are mass-produced and available at low price, the job needs simple surface facilities, and customary human force to operate the RCC method. Consequently, the
Traditional gas-lift technology blossomed between 1929 and 1945, with about 25000 patents being issued during this time
The concept of High Pressure Gas-lift (herein after referred to as HPGL), as discussed in SPE 14347
The case for eliminating failure-prone gas-lift valves is self-evident. However, the case for the second application will be proffered. Conventional gas-lift, while recognized as excellent for producing high volumes of solids- laden fluid from deviated wells, underperforms ESP's in new horizontal oil wells due to frictional losses associated with high tubing flowrates. The case will be made that SPGL combined with reverse flow mitigates the frictional losses associated with high flowrates. Similar to a coil tubing cleanout using high pressure nitrogen, high pressure natural gas can lift large volumes of fluid without the need for gas-lift valves.
Technology and products for HPGL currently exist. Multiple compressor designs will be summarized to show that only one additional stage of compression is needed to support HPGL, with three and four stage designs being capable of performing the task. The recommendation will be made that HPGL compressors be assembled from readily available components, and that multiple pilot tests be made by industry. The importance of maintaining temperatures through the compression process high enough to prevent hydrocarbon condensation will also be explained.
The initial reservoir fluid distribution in the Prudhoe Bay Reservoir, Alaska, consisted of relatively planar gas-oil and oil-water contacts. These contacts were soon perturbed by production as well as water and gas reinjection. Understanding the current reservoir fluid distribution and the movement of fluids in response to reservoir depletion mechanisms is key to optimizing and maximizing recovery.
Historically, the focus of much of the successful cased hole surveillance effort in the Gravity Drainage area of Prudhoe Bay has been directed at tracking the movement of the gas-oil contact and quantifying the remaining oil bypassed by gravity drainage processes. Forward modelling of pulsed neutron tool attributes has been employed to enable gas saturation quantification. Recent introduction of memory Multi-Detector Pulsed Neutron technology has enabled the quantification of bypassed oil in horizontal wells using coiled-tubing. Selective perforation has been used to access undrained oil.
In the Waterflood area of Prudhoe Bay, it is a challenge to use conventional sigma logs to distinguish between oil and water due to the relatively low and variable formation and injection water salinity. Consequently, continuous and multiple passes and stationary Carbon- Oxygen logs have been employed to identify bypassed oil.
In areas of the field where gas, oil and water columns exist in a single wellbore, both Carbon-Oxygen and Multi-Detector Pulsed Neutron nuclear attributes are combined together using a novel three phase interpretation technique to quantify oil, gas and water saturation. The technique has been applied in a number of Prudhoe Bay wells to enhance understanding of the fluid distribution and to design perforation strategies to maximize offtake in existing cased hole wells.
Case studies of each scenario illustrate the use and integration of Carbon-Oxygen and Multi-Detector Pulsed Neutron attributes to identify bypassed oil.